Embodiments of the present disclosure relate to the field of measuring multiphase flow of fluids in a hydrocarbon-bearing reservoir, well or pipe. More particularly, embodiments of the present disclosure may provide an apparatus that measures multiphase flow of fluids in a surface production pipe connected to such hydrocarbon-bearing reservoirs. Further, the invention relates to a method of measuring multiphase flow of fluids produced by/from a hydrocarbon-bearing reservoir.
The measurement of flowrates of the multiphase flow of flow of oil, gas and water flowing through a hydrocarbon-bearing reservoir pipeline is an important consideration for production management of a well. Techniques for measuring such flowrates are generally well known and there are two types of well-known approaches to multiphase flow measurement.
One known technique is to measure the flow as a well-mixed mixture of different phases, (liquid and gas, predominantly) in which global parameters such as mixture density and velocity are measured to determine the flow rates. For the gas phase, which typically travels faster than the liquids, slip correlation is used to estimate its velocity. A typical example of this type is the commercial Vx flowmeter produced by Schlumberger, which combines nuclear based phase fraction measurements with Venturi-based differential pressure measurement to determine the flow rates of the multiphase fluid.
A second technique is to separate out the phases, according to their densities, so that separate velocity and holdup measurements can be applied to each of the individual phases. In such a technique, often via a swirl generator, the multiphase flow is separated into an annular flow with a gas core and a liquid annulus. Ultrasonic techniques may be used to measure the liquid fraction and velocity, and the flow rate of the liquid phase can be derived from these measurements. The liquid holdup and velocity measured by ultrasound can then be combined with the differential pressure measurement across a Venturi flowmeter to derive gas flow rate.
The swirl based flowmeter has several limitations, however, namely the separation of gas from liquid is affected by trapped microsized gas bubbles in the liquid layer that are difficult to remove, particularly when the liquid is viscous. Thus, the presence of micro gas bubbles makes ultrasound propagation through the liquid layer difficult, leading to erroneous liquid holdup and velocity measurements.
Moreover, based on the time-of-flight measurement principle, the accuracy of the ultrasonically measured holdup is limited by the unknown speed of sound in the liquid phase. Further, the operational range of the flowmeter is limited, with a typical turn-down ratio of around three (3). The lower end of the range is reached when the liquid flow rate drops to a level that no longer carries sufficient momentum to produce a swirl; the higher end is limited by the total pressure drop across the meter, which can be several times more than that produced by a Venturi when no swirl is used. This high pressure drop may be an issue for field where pressure may be used to control the flow of the mixture.